A plunger lift is an apparatus that is used to increase the productivity of oil and gas wells. As today's companies implement cost containment and resource allocation measures in response to lower product prices, the use of a plunger lift production method should be considered because it can be one of the most economical methods of production. Large returns are possible from a relatively small capital expenditure. This is particularly true for marginal wells.
The cost-effectiveness of plunger lift methodology can be characterized by at least three features: low initial costs, low annual maintenance costs, and the ability to better utilize other field assets. The benefits of these features are lower overall costs and lower unit production costs.
A typical plunger lift application can cost less than $5,000 per installation as compared to $20,000 to $40,000 for beam lift. Plunger lift costs typically do not increase with well depth and annual maintenance costs can range from $500 to $1,000 versus $5,000 to $10,000 for beam lift.
Other benefits can include: better utilization of an operator's time, reduction of environmental liability concerns from not venting hydrocarbons into the atmosphere (blowing), and applications are not typically limited by depth. Although systems have been successfully installed on wells as deep as 26,000 feet, even greater depths may be achieved.
There are five common applications for plunger lifts: 1). gas well liquid unloading; 2). oil production with associated gas; 3). gas wells with coiled tubing; 4). control scale and paraffin; and 5). intermittent gas lift.
In the early stages of a well's life, liquid loading is usually not a problem. When rates are high, the well liquids are carried out of the tubing by the high velocity gas. As a well declines, a critical velocity is reached below which the heavier liquids do not make it to the surface and start to fall back to the bottom exerting back pressure on the formation, thus loading up the well. A plunger system is a method of unloading gas in high ratio oil wells without interrupting production. In operation, the plunger travels to the bottom of the well where the loading fluid is picked up by the plunger and is brought to the surface removing all liquids in the tubing. The plunger also keeps the tubing free of paraffin, salt or scale build-up. A plunger lift system works by cycling a well open and closed. During the open time a plunger interfaces between a liquid slug and gas. The gas below the plunger will push the plunger and liquid to the surface. This removal of the liquid from the tubing bore allows an additional volume of gas to flow from a producing well. A plunger lift requires sufficient gas presence within the well to be functional in driving the system. Oil wells making no gas are thus not plunger lift candidates.
As flow rate and pressures decline in a well, lifting efficiency can decline. Before long the well could begin to “load up”. This is a condition whereby the gas being produced by the formation can no longer carry the liquid being produced to the surface. There are two reasons this occurs. First, as liquid comes in contact with the wall of the production string of tubing, friction occurs. The velocity of the liquid is slowed and some of the liquid adheres to the tubing wall, creating a film of liquid on the tubing wall. This liquid may not reach the surface. Secondly, as the flow velocity continues to slow the gas phase may no longer support liquid in either slug form or droplet form. This liquid along with the liquid film on the sides of the tubing, may fall back to the bottom of the well. In a very aggravated situation, there could be liquid in the bottom of the well with only a small amount of gas being produced at the surface. The produced gas must bubble through the liquid at the bottom of the well and then flow to the surface. Because of the low velocity, very little liquid, if any, is carried to the surface by the gas. A plunger lift will act to remove the accumulated liquid, thereby improving well efficiency.
A typical installation plunger lift system 100 can be seen in FIG. 1. A lubricator assembly 10 is one of the most important components of plunger system 100. Lubricator assembly 10 includes a cap 1, an integral top bumper spring 2, a striking pad 3, and an extracting rod 4. Extracting rod 4 may or may not be employed depending on the plunger type. Below lubricator assembly 10 is a plunger auto catching device 5 and a plunger sensing device 6. Sensing device 6 sends a signal to a surface controller 15 upon the arrival of a plunger 200 at the well top. Plunger 200 is shown to represent the plunger of the present invention and will be described below in more detail. Sensing the plunger is used as a programming input to achieve the desired well production, flow times and wellhead operating pressures. A master valve 7 should be sized correctly for a tubing 9 and plunger 200. An incorrectly sized master valve will not allow plunger 200 to pass. Master valve 7 should incorporate a full bore opening equal to tubing 9 size. An oversized valve will allow gas to bypass the plunger causing it to stall in the valve. If the plunger is to be used in a well with relatively high formation pressures, care must be taken to balance tubing 9 size with a casing 8 size. The bottom of a well is typically equipped with a seating nipple/tubing stop 12. A spring standing valve/bottom hole bumper assembly 11 is located near the tubing bottom. The bumper spring is located above the standing valve and can be manufactured as an integral part of the standing valve or as a separate component of the plunger system.
Surface control equipment usually consists of motor valve(s) 14, sensors 6, pressure recorders 16, etc., and an electronic controller 15 which opens and closes the well at the surface. Well flow ‘F’ proceeds downstream when surface controller 15 opens well head flow valves. Controllers operate on time, or pressure, to open or close the surface valves based on operator-determined requirements for production. Modern electronic controllers incorporate features that are user friendly, easy to program, addressing the shortcomings of mechanical controllers and early electronic controllers. Additional features include: battery life extension through solar panel recharging, computer memory program retention in the event of battery failure and built-in lightning protection. For complex operating conditions, controllers can be purchased that have multiple valve capability to fully automate the production process.
Standard downhole bypass plungers typically have vertical corridors built into them to allow fluids to pass through the plunger during a descent. These corridors are closed when the plunger strikes the bottom of the well and during plunger ascent. When the corridors are open, the plunger falls quickly against flow. Bypass plungers may be used with strong gas wells, flowing wells, and wells that make a lot of fluid. The size of the vertical corridors of a standard bypass plunger cannot typically be varied during the fall or rise of the plunger. Onr type of a standard non bypass plunger operates by pushing its way through fluids, wherein the fluids must flow between the small area between the tubing and the outside of the plunger. Such plungers, without flow through vertical corridors will fall much slower than a plunger with open vertical corridors. When rising near the surface, a plunger with slightly open vertical corridors will slow down signifying that it is losing its seal.
Fall rates of about 1000 to about 2000 feet per minute (fpm) through gas have been experienced. Foss and Gaul reported a 2000 fpm plunger fall rate and incorporated this value into their calculations. Bypass type plungers fall at rates of about 3000 to about 3500 fpm. Abercrombie found that this rate may be too aggressive for general applications, and used a 1000 fpm value in his calculations. If pad, wobble washer or blade plungers are being used, the fall rate can generally be as low as 175 fpm through gas.
Plunger fall rates through liquid range from 17 fpm to 250 fpm. Foss and Gaul used 172 fpm in their calculations.
Plunger rise rates average between about 750 to about 2000 fpm. A common rise rate used is 1000 fpm. In general, the lower the upward velocity, the more efficient the application will be. The drawback to low upward velocity is the possibility of a plunger stalling. If a good seal exists between the plunger and tubing, an operator can attempt to bring the plunger up at speeds less than 1000 fpm. Lower speeds will allow the operator to maintain the well at a lower average casing pressure, and this will maximize reservoir drawdown. The disclosed device can help to slow the plunger's rise, thus optimizing well operation, and minimizing plunger stall.
Since plungers weigh several pounds, they can act as a projectile when traveling at a fall rate of up to about 3500 fpm, or about 30–45 miles per hour (mph). The impact force of a ten-pound projectile, for example, traveling at over 30 mph can clearly impart damage to downhole equipment that it slams against in order to stop while falling downhole. The same problem can exist for rising plungers.
Not only can the disclosed plunger automatically slows down at the bottom (or top) portion of its travel, it can do so without impact. The present invention provides a thermal actuated valve that motivates fluid to flow in or around the plunger as fluid temperature increases or decreases. Thus the plunger's apertures and speeds can be controllable in relation to ambient temperatures.
A wax-filled canister or equivalent can expand internally downhole and move a piston to motivate a valve in a fluid passage corridor in a plunger. When the corridor is closed, the plunger can no longer efficiently pass downhole fluids through it as it falls. Therefore, the temperature of the downhole fluids acts to provide a breaking action on the descending plunger. Production operators can save money with a reduction of broken downhole plunger stops, plungers and the reduction of downtime. An alternate embodiment uses a thermal actuator(s) to expand an outer casing of the plunger, thereby slowing the speed of the plunger.